Wettability describes the preference of a solid to be in contact with one fluid over another based on the balance of surface and interfacial forces. A drop of a preferentially wetting fluid will displace another fluid; at the extreme it will spread over the entire surface. Conversely, if a non-wetting fluid is dropped onto a surface already covered by the wetting fluid, it will bead up, minimizing its contact with the solid. If the condition is neither strongly water-wetting nor strongly oil-wetting, the balance of forces in the oil/water/solid system will result in a contact angle, θ, between the fluids at the solid surface. See e.g., FIG. 1.
In many oilfield applications, wettability is considered in a binary manner—the rock is either water-wet or oil-wet. However, this simplification masks considerable complexity of wetting physics in reservoir rock. In actuality, degrees of intermediate wetting apply along the continuum between strongly oil wetting and strongly water wetting.
Typically, the primary constituents of reservoirs—quartz, carbonate and dolomite—are water-wet prior to oil migration. However, reservoir rocks are complex, including a variety of mineral types with different wettabilities, making the wetting character of the composite rock difficult to describe.
Another complexity is the saturation history of the material, which may influence surface wetting, such that pore surfaces that had been previously contacted by oil may be oil-wet, but those never contacted by oil may be water-wet. Various terms have been used to describe both of these conditions, including mixed-, fractional- and dalmation-wetting.
Herein, the term “mixed-wetting” will be used for any material with inhomogeneous wetting. It is important to note the distinctions between intermediate-wetting (lacking a strong wetting preference) and mixed-wetting (having a variety of preferences, possibly including intermediate-wetting) conditions.
Another important distinction is that a preferentially water-wetting surface can be in contact with oil or gas. Wettability does not describe the saturation state: it describes the preference of the solid for wetting by a certain fluid, given the presence of that preferred wetting fluid. Thus, a water-wet rock can be cleaned, dried and fully saturated with an alkane/mineral oil, while the surfaces in the pores remain water-wet.
Strictly speaking, the term “imbibition” refers to an increase in the saturation of the wetting phase, whether this is a spontaneous imbibition process or a forced imbibition process such as a waterflood in a water-wet material. Conversely, “drainage” refers to an increase in saturation of the nonwetting phase. However, in practice, the term imbibition is used to describe a process with increasing water saturation, and drainage is used to describe a process with increasing oil saturation, and one should be careful when reading the literature to determine which sense is being used.
Several methods are available to measure a reservoir's wetting preference. Oil recovery obtained from imbibition and waterflooding experiments, contact angle measurements and Nuclear Magnetic Resonance (NMR) measurements are the most commonly used methods.
The Amott-Harvey imbibition test is commonly used, for example. A sample at irreducible water saturation and saturated with oil, Swirl', placed into a water-filled imbibition apparatus spontaneously imbibes water over a period of time—at least 10 days, and sometimes much longer. Then the sample is placed in a flow cell and water is injected, with the additional oil recovery noted. The sample is now at residual oil saturation, Sor, and the process is repeated with an oil-filled imbibition apparatus, and then an oil-flooding apparatus. Separate ratios of spontaneous imbibition to total saturation change for water, Iw, and oil, Io, are termed the water and oil imbibition indices, respectively. The Amott-Harvey index is the difference between the water and oil ratios. The result is a number between +1 (strongly water-wetting) and −1 (strongly oil-wetting).
In the US Bureau of Mines (USBM) test, a centrifuge spins the core sample at stepwise increasing speeds. The sample starts at irreducible water saturation and saturated with oil, Swirr in a waterfilled tube. After periods at several spin rates, the sample reaches residual oil saturation, Sor, and it is placed into an oil-filled tube for another series of measurements. The areas between each of the capillary-pressure curves and the zero capillary-pressure line are calculated, and the logarithm of the ratio of the water-increasing to oil-increasing areas gives the USBM wettability index (FIG. 2). The measurement range extends from +∞ (strongly water wetting) to −∞ (strongly oil wetting), although most measurement results are in a range of +1 to −1. The centrifuge method is fast, but the saturations must be corrected because the centrifuge induces a nonlinear capillary-pressure gradient in the sample.
It is possible to combine the Amott-Harvey and USBM measurements by using a centrifuge rather than flooding with water and oil to obtain the forced flooding states. The Amott-Harvey index is based on the relative change in saturation, while the USBM index gives a measure of the energy needed to make the forced displacement, making them related, but independent indicators of wettability.
NMR has also been used as a tool to measure wettability. The wettability conditions in a porous media containing two or more immiscible fluid phases determine the microscopic fluid distribution in the pore network. NMR measurements are sensitive to wettability because of the strong effect that the solid surface has on promoting magnetic relaxation of the saturating fluid.
The idea of using NMR as a tool to measure wettability was presented by Brown and Fatt in 1956. Their theory was based on the hypothesis that molecular movements are slower in the bulk liquid than at the solid-liquid interface. In this solid-liquid interface the diffusion coefficient is reduced, which correspond to a zone of higher viscosity. In this higher viscosity zone, the magnetically aligned protons can more easily transfer their energy to their surroundings. The magnitude of this effect depends upon the wettability characteristics of the solid with respect to the liquid in contact with the surface.
These methods only measure wettability as a function of the final oil recovery or saturation and therefore, represent only the displacement efficiency. However, oil production rates are also an important factor in evaluating a reservoir and it has been observed that oil production rates from rocks with different wettabilities vary. It has also been observed that the final oil recovery may vary for rocks with similar wettability conditions. Furthermore, other popular methods of wettability measurement, such as measuring contact angle against a known surface, do not accurately predict the wettability of a heterogeneous reservoir rock.
Therefore, what is needed in the art are better methods of assessing wettability, in particular methods that allow for corrections for variations in core properties, sample size and geometry.